1. Field of the Invention
The invention relates to the field of oil and gas exploration and development and, more particularly, to a system for more accurately assessing the fluid distribution of subsurface reservoirs.
2. Background
Subterranean reservoirs of natural gas and petroleum, hereinafter referred to generically as xe2x80x9chydrocarbonsxe2x80x9d, are typically found trapped in permeable geological strata beneath a layer of impermeable strata material. Normally ground water, typically referred to as xe2x80x9cconnatexe2x80x9d water, will be present in the reservoir along with the hydrocarbon. Because hydrocarbons are lighter than water, the hydrocarbons will accumulate toward the top of a reservoir and water will occupy the bottom portion of the reservoir. Typically, a transition zone will exist between the two fluids. In some regions, impermeable layers may be relatively closely stacked atop one another, trapping numerous zones of what may be hydrocarbons, water or a combination of water and hydrocarbons between impermeable layers. A wellbore penetrating a subsurface formation may penetrate a plurality of zones containing hydrocarbons and/or water. The estimation of water saturation vs. hydrocarbon saturation in these zones, and the estimation of which of these zones are hydraulically connected aids in the estimation of the amount of hydrocarbons in place and volumes of hydrocarbons which may be recovered, and in the selection of completion intervals.
Large sums are expended in performing well logging and in obtaining cores from wells and in examining these well logs and cores, in order to evaluate reservoir characteristics. Various methods have also been developed for analyzing reservoir characteristics.
The article by Christopher and Bob Harrison, An Integrated Approach to Saturation Height Analysis, from the SPWLA 36th Annual Logging Symposium, Jun. 26-29, 1995, discussed hydrocarbon distributions within the reservoir in terms of the saturation height function. The article states that the general form of the function relating hydrocarbon saturation Sh to height above free water level h is:                                           S            h                    =                                    1              -                              S                ω                                      =                          a              ⁢                              xe2x80x83                            ⁢                                                exp                  ⁡                                      (                                                                  -                        b                                                                    h                        +                        d                                                              )                                                  c                                                    ,                            (                  Eq          .                      xe2x80x83                    ⁢          1                )            
and for capillary pressure PC measurements the equivalent expression is:                               S          h                =                              1            -                          S              ω                                =                      a            ⁢                          xe2x80x83                        ⁢                                                            exp                  ⁡                                      (                                                                  -                        b                                                                                              P                          c                                                +                        d                                                              )                                                  c                            .                                                          (                  Eq          .                      xe2x80x83                    ⁢          2                )            
The article further states that Sxcfx89is water saturation and, depending on the context, a, b, c, and d are constants, or alternatively they may be simple function of rock properties such as permeability. The article also states that a formulation is presented so that each term in the function can be related directly to a physical parameter such as irreducible water saturation, ratio of contact angle and surface tension between laboratory and reservoir conditions, threshold capillarity entry pressure, and height differences between free water level and oil water contact.
The Technical Note, Introduction of a Pore Geometrical Factor Defined by the Capillary Pressure Curve, Journal of Petroleum Technology, March, 1960, p. 73-77, by J. H. M. Thomeer, provides a mathematical description of capillary pressure curves. The technique is said to be based on the observation that the location and shape of a capillary pressure curve reflect characteristics of the pore structure of the sample. It is stated that regarding the location and shape of a capillary pressure curve in which core saturation is plotted as a function of pressure: xe2x80x9cThe location of the curve with respect to the (Vb)Pc and Pc axes is a measure of the interconnected pore volume and of the cross-sectional area of the pore first entered by mercury, respectively. The shape of the curve depends on the interconnection of the pores and the sorting of the pore size.xe2x80x9d Pc is stated to be the mercury/air capillary pressure psia, and (Vb)Pc the fractional bulk volume occupied by mercury at Pressure Pc. It is noted that: xe2x80x9cSome capillary pressure curves show two plateaus at different pressures. These so called xe2x80x9cdouble curvesxe2x80x9d may be expected when capillary pressure curves are run, for example, on vuggy limestone samples or samples composed of sand silt laminations. . . . Physical rock properties depending primarily on the relatively larger pores of a sample are expected to be related to the parameters of the lower pressure curve. For example, the contribution to permeability by the relatively finer pores is often negligible compared to that of the relatively larger pores. An example of a double curve is shown in FIG. 5.xe2x80x9d
The article Comparison Between Log and Capillary Pressure Data to Estimate Reservoir Wetting, SPE 6856, 1977, by Michael Holmes and Douglas B. Tippie, presents a method whereby comparison of capillary pressure measurements with logs can be used to estimate in-situ wetting. The article includes a discussion of the conversion of capillary pressure at reservoir conditions into an equivalent height above the oil-water contact.
U.S. Pat. No. 5,621,169, which issued on Apr. 15, 1997 to Harris et al., discloses a method for predicting the hydrocarbon/water contact level for oil and gas wells which relates porosity "PHgr", water saturation Sxcfx89, air permeability ka and capillary pressure Pc. The hydrocarbon/water contact levels are predicted through regression analysis using porosity "PHgr", water saturation Sxcfx89, air permeability ka from well log and core analysis information. The articles by Joseph M. Hawkins, Donald L. Luffel and Thomas G Harris, Capillary pressure model predicts distance to gas/water, oil/water contact, Oil and Gas Journal, Jan. 18, 1993, pp 38-43; and by R. P. Alger, D. L. Luffel and R. B. Truman, New Unified Method of Integrating Core Capillary Pressure Data With Well Logs, SPE, June, 1989, p. 145-152, provide further discussion of the method discussed in U.S. Pat. No. 5,621,169.
U.S. Pat. No. 4,903,207, which issued on Feb. 20, 1990 to Alger et al., discloses, for a formation zone of a well, a method for determining the relationship between bulk volume of oil as a function of total effective formation porosity and height above the oil water contact from capillary pressure data of a core taken from the formation of the well. It is stated that it is one object of the invention to provide a method for determination of height h above the oil-water contact of a reservoir at a particular depth d (and consequently the water level WL=d+h) where no wells with open-hole logs have been drilled deep enough to penetrate and locate the depth of the oil-water contact, but capillary pressure data are available from analysis of cores taken from at least one well.
A long felt and continuing need continues to exist, however, for a system for more accurately assessing the fluid distribution of subsurface reservoirs.
It should be noted that the description of the invention which follows should not be construed as limiting the invention to the examples and preferred embodiments shown and described. Those skilled in the art to which this invention pertains will be able to devise variations of this invention within the scope of the appended claims.
In one embodiment the invention comprises a method for generating a log of a subsurface formation, in which data from well logging measurements are utilized to derive a relationship between porosity and irreducible water saturation for the formation and the derived relationship between porosity and irreducible water saturation is applied to a porosity log of the subsurface formation to generate a log of irreducible water saturation.
In another embodiment the invention comprises a method for calculating a theoretical water saturation log for a subsurface formation which utilizes a relationship based on porosity, irreducible water saturation and height above the petroleum-water contact level. In one implementation of the invention the relationship is:
(Height)(Sxcfx89theorxe2x88x92Sxcfx89i)=PCHYPMOVEDxe2x80x83xe2x80x83(Eq. 3)
wherein Height is the height in a hydraulic unit above the petroleum-water contact level,
Sxcfx89theor is the calculated water saturation,
Sxcfx89i is irreducible water saturation, and
PCHYPMOVED is related to porosity.